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Medina, Dayana

From: Medina, Dayana

Sent: Thursday, August 29, 2013 1:02 PM

To: Pettyjohn, Mary

Cc: Donaldson, Guy

Subject: Region 6 comments on AECC Bailey and McClellan BART analysis

Hi Mary,  

Here are our comments on the AECC Bailey and McClellan BART analyses. For SO2 BART, we believe that you have

reached a reasonable conclusion, but additional information would help support your analysis. We also have some

remaining concerns with the NOx BART analysis. Please let me know if you’d like to discuss.  

New Base Case for SO2

 In comments provided to ADEQ on 12/13/12, we asked that the BART analysis include a justification for the use of a

new base case for SO2 and that documentation be provided of the historical actual sulfur content of the fuel oil

burned at the two units. AECC revised the BART analysis to explain that the new base case values are representative

of the average from 2009‐2011 and are also consistent with the previous baseline years of 2001‐2003. However, no

documentation of the sulfur content of the fuel oil burned has been provided. Please provide this documentation to

justify the new base case.  

Cost Analysis for Fuel Switching (SO2 BART)

 In a conference call with ADEQ and AECC in August 2012, AECC indicated the cost analysis for fuel switching may

have been based on outdated fuel oil cost numbers thereby potentially resulting in a cost overestimation when

compared to the cost in today’s market. However, the revised BART analysis does not include any changes to the

cost estimates and language was added stating that the cost numbers are based on current vendor estimates for

fuel oil with varying levels of sulfur, and are in fact representative of today’s market available at Bailey and

McClellan. Please provide a copy of the vendor’s estimates. Additionally, the cost estimates shown on Tables 5‐9 and

5‐10 indicate that the cost of the base case fuel is $4.68/MMBtu at Bailey and $5.70/MMBtu at McClellan. However,

footnote 7 states the cost estimate provided by the vendor for this type of fuel oil (i.e., No. 6 fuel oil with sulfur

content between 1.0 ‐ 2.0%) is between $16.00MMBtu ‐ $16.50MMBtu. This would indicate that the cost differential

of fuel switching is actually lower than what is currently estimated. Please explain the apparent discrepancy in the

cost estimates for the base case fuel oil.  

Modeling for SO2 BART

 As we stated in comments provided to ADEQ on 12/13/12, section 1 of the BART analysis indicates the pre‐control

visibility impairment of each unit is based on modeling of emission rates that were derived from stack testing, CEMS,

and AP‐42 emission factors. However, it is still unclear how stack testing was used to derive any of the emission

rates modeled. Please explain how stack testing was used.  

 As we stated in our previous comments to ADEQ, the revised baseline max 24‐hour PM emission rates (see Table 4‐

1) are significantly lower than those used in the original BART analysis and appear to be inconsistent with AP‐42

emission factors and the maximum burner capacities. Please explain the revised PM emission rates and provide the

PM emission estimation calculations.  

 In our previous comments to ADEQ we stated that even though the visibility impacts from PM are relatively small for

both units, the visibility modeling of fuel switching scenarios should include the decrease in PM emissions

anticipated from switching to lower sulfur fuels. Since the PM emission rates modeled did not account for the

decreases in PM emissions as a result of fuel switching, we asked that a brief discussion be included in the BART

analysis on the impact of reductions of PM emissions on visibility. Footnote 8 was added to explain that the PM

emission rates for the lower sulfur fuel scenarios are conservatively assumed to equal the baseline (i.e., higher)
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sulfur fuel scenario. However, a discussion of the expected impact that adjusting the PM emission rates (to account

for the decrease in PM emissions in lower sulfur fuels) would have on the modeled visibility benefits has not been

provided.  

 A new paragraph was added to page 5‐10 of the BART analysis, indicating AECC’s disagreement with our previous

comment about the need to use the maximum emission rate from the baseline period (instead of the rolling 30‐day

average) to calculate the SO2 emission rates to model for the fuel switching scenarios. We continue to stand by our

previous comment concerning this, and believe that if AECC chooses to not re‐model at this time, then a discussion

should be included of the impact, if any, that using the maximum emission rates would have on the modeling results

and the ultimate BART determination.  

 In our previous comments, we asked that the BART analysis include a plot showing the meteorological domain,

computational modeling domain, location of sources, and Class I area receptor locations used in the visibility

analysis. This plot has not been provided in the revised BART analysis.  

General comments on NOx BART

 The new introductory section in the NOx BART analysis states that “As in the original submittal, it is proposed to

burn natural gas as the primary fuel and switch to low‐sulfur fuel oil as the back‐up fuel.” As written, this statement

seems confusing and out of place, as it is referring to BART for SO2, and the SO2 BART analysis proposes to switch to

fuels with 0.5% sulfur or less to satisfy BART. The SO2 BART analysis makes no mention of proposing BART to be the

burning of natural gas as the primary fuel and low sulfur fuel oil to be burned only as the back‐up fuel. Therefore, we

recommend that this statement be revised or removed from the introduction.

 Footnote 1 was added, stating that “The previously submitted SO2 and PM analyses were verbally agreed upon by

EPA in an August 16, 2012 conference call to discuss the July 24, 2012 submittal.” We remind ADEQ that we

communicated that we generally agreed with the SO2 and PM BART determinations, but that certain issues needed

to be addressed, in particular additional documentation should be provided, to help support the analysis. To date,

not all of these issues have been addressed, as discussed in our comments above.

NOx Control Case Emission Rates

 Section 1.4.1.3 and Table 1‐2 state that based on the estimate provided by Babcock Power Services, the NOx

emission rate expected from the combination of LNB/OFA/FGR is 0.15 – 0.20 lb/MMBtu for both natural gas and fuel

oil firing scenarios. However, the copy of the estimate from Babcock Power Services (Appendix C) indicates that the

expected emission rate is 0.15 – 0.20 lb/MMBtu for natural gas firing, and 0.35 lb/MMBtu for fuel oil firing. Please

explain the inconsistency. We also note that Table 1‐2 indicates the baseline NOx emission rate for Bailey Unit 1 for

fuel oil firing is 0.30 lb/MMBtu, which is actually lower than Babcock Power Services’s expected emission rate of

0.35 lb/MMBtu using LNB/OFA/FGR. Please provide an explanation addressing this.

 The estimate provided by Babcock Power Services for the capital cost of combustion controls and the expected

controlled emission rates, is for “Low NOx Natural Gas burners (#6 secondary fuel), OFA, and FGR system (10%).”

Please explain whether the 10% refers to the percentage of flue gas recirculated or to the NOx removal efficiency of

FGR alone. We note that FGR technology is typically capable of recirculating 20‐30% of the flue gas back to the

combustion zone. As you know the RH rule requires that in analyzing controls for BART, the most stringent emission

control level that the technology is capable of achieving must be taken into account (70 FR 39166). ADEQ should

ensure this requirement has been met.

Cost Analysis for NOx Controls

 The capital costs for NOx combustion controls are based on the estimate provided by Babcock Power Service.

However, the O&M costs for combustion controls are still based on equations from the 2005 ERG report prepared

for the WRAP and based on coal fired EGU data. It has not been demonstrated that the data and costing methods

used are appropriate and applicable to the natural gas/fuel oil Bailey and McClellan units. If it is not possible for

AECC to incorporate site‐specific O&M costing information in the cost‐analysis, a brief discussion should be provided

of how the costs calculated using the equations from the ERG report are in line with the actual costs of combustion

controls at natural gas/fuel oil fired units similar to the Bailey and McClelland units.
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 The cost evaluation for combustion controls provided in Appendix A indicates it applies to LNB/OFA capital and

O&M costs. However, based on the capital costs shown, it appears that the cost information presented in the table

applies to LNB/OFA/FGR. If that is the case, please correct the title of the cost evaluation accordingly.

Thank you,  

Dayana Medina

U.S. Environmental Protection Agency, Region 6

Multimedia Planning and Permitting Division

Air Planning Section (6PD‐L)

214‐665‐7241